10-K 1 ava-20131231x10k.htm 10-K AVA-2013.12.31-10K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
__________________________________________________________________________________________
Form 10-K
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED December 31, 2013 OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM              TO             
Commission file number 1-3701
__________________________________________________________________________________________
AVISTA CORPORATION
(Exact name of Registrant as specified in its charter)
Washington
 
91-0462470
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
1411 East Mission Avenue, Spokane, Washington
 
99202-2600
(Address of principal executive offices)
 
(Zip Code)
Registrant’s telephone number, including area code: 509-489-0500
Web site: http://www.avistacorp.com

Securities registered pursuant to Section 12(b) of the Act:
Title of Class
 
Name of Each Exchange on Which Registered
Common Stock, no par value
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Title of Class
Preferred Stock, Cumulative, Without Par Value
__________________________________________________________________________________________ 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.    Yes  ¨    No  x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days:    Yes  x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x
Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
x
Accelerated filer
¨
Non-accelerated filer
¨ (Do not check if a smaller reporting company)
Smaller reporting company
¨



Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):    Yes  ¨    No  x
The aggregate market value of the Registrant’s outstanding Common Stock, no par value (the only class of voting stock), held by non-affiliates is $1,620,660,221 based on the last reported sale price thereof on the consolidated tape on June 30, 2013.
As of January 31, 2014, 60,111,948 shares of Registrant’s Common Stock, no par value (the only class of common stock), were outstanding.
__________________________________________________________________________________________
Documents Incorporated By Reference
Document
 
Part of Form 10-K into Which
Document is Incorporated
Proxy Statement to be filed in connection with the annual meeting of shareholders to be held on May 8, 2014.
Prior to such filing, the Proxy Statement filed in connection with the annual meeting of shareholders held on May 9, 2013.
 
Part III, Items 10, 11,
12, 13 and 14



AVISTA CORPORATION



INDEX 
Item
No.
 
 
Page
No.
 
 
 
 
 
 
 
 
 
 
 
 
Part I
 
 
1
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1A.
 
 
1B.
 
 
2
 
 
 
 
 
3
 
 
4
 
*
 
 
Part II
 
 
5
 
 
6
 
 
7
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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7A.
 
 
8.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
9.
 
*
9A.
 
 
9B.
 
 
 
 
Part III
 
 
10.
 
 
11.
 
 
12.
 
 
13.
 
 
14.
 
 
 
 
Part IV
 
 
15.
 
 
 
 
 
 
 
 
 * = not an applicable item in the 2013 calendar year for Avista Corp.
 

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ACRONYMS AND TERMS
(The following acronyms and terms are found in multiple locations within the document)
Acronym/Term
Meaning
aMW
-
Average Megawatt - a measure of the average rate at which a particular generating source produces energy over a period of time
AEL&P
-
Alaska Electric Light & Power Company, the primary operating subsidiary of AERC
AERC
-
Alaska Energy and Resources Company, a privately-held company based in Juneau, Alaska. The Company entered into an agreement and plan of merger with AERC on November 4, 2013.
AFUDC
-
Allowance for Funds Used During Construction; represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period
AM&D
-
Advanced Manufacturing and Development, does business as METALfx
ASC
-
Accounting Standards Codification
Avista Capital
-
Parent company to the Company’s non-utility businesses
Avista Corp.
-
Avista Corporation, the Company
Avista Energy
-
Avista Energy, Inc., an electricity and natural gas marketing, trading and resource management business, subsidiary of Avista Capital. This entity is currently inactive; however, we still incur legal fees associated with this entity.
Avista Utilities
-
Operating division of Avista Corp. comprising the regulated utility operations
BPA
-
Bonneville Power Administration
Capacity
-
The rate at which a particular generating source is capable of producing energy, measured in KW or MW
Cabinet Gorge
-
The Cabinet Gorge Hydroelectric Generating Project, located on the Clark Fork River in Idaho
Colstrip
-
The coal-fired Colstrip Generating Plant in southeastern Montana
Coyote Springs 2
-
The natural gas-fired Coyote Springs 2 Generating Plant located near Boardman, Oregon
CT
-
Combustion turbine
Deadband or ERM deadband
-
The first $4.0 million in annual power supply costs above or below the amount included in base retail rates in Washington under the Energy Recovery Mechanism in the state of Washington
Dekatherm
-
Unit of measurement for natural gas; a dekatherm is equal to approximately one thousand cubic feet (volume) or 1,000,000 BTUs (energy)
Ecology
-
The state of Washington’s Department of Ecology
Ecova
-
Ecova, Inc., a provider of facility information and cost management services for multi-site customers and energy efficiency program management for commercial enterprises and utilities throughout North America, subsidiary of Avista Capital. Formerly known as Advantage IQ, Inc. (Advantage IQ)
Energy
-
The amount of electricity produced or consumed over a period of time, measured in KWH or MWH. Also, refers to natural gas consumed and is measured in dekatherms.
EPA
-
Environmental Protection Agency
ERM
-
The Energy Recovery Mechanism, a mechanism for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Washington
FASB
-
Financial Accounting Standards Board
FERC
-
Federal Energy Regulatory Commission
GAAP
-
Generally Accepted Accounting Principles
GHG
-
Greenhouse gas
IPUC
-
Idaho Public Utilities Commission
IRP
-
Integrated Resource Plan
Jackson Prairie
-
Jackson Prairie Natural Gas Storage Project, an underground natural gas storage field located near Chehalis, Washington
kV
-
Kilovolt (1000 volts): a measure of capacity on transmission lines
KW, KWH
-
Kilowatt (1000 watts): a measure of generating output or capability. Kilowatt-hour (1000 watt hours): a measure of energy produced.

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Lancaster Plant
-
A natural gas-fired combined cycle combustion turbine plant located in Idaho
MPSC
-
Public Service Commission of the State of Montana
MW, MWH
-
Megawatt: 1000 KW. Megawatt-hour: 1000 KWH.
NERC
-
North American Electricity Reliability Corporation
Noxon Rapids
-
The Noxon Rapids Hydroelectric Generating Project, located on the Clark Fork River in Montana
OPUC
-
The Public Utility Commission of Oregon
PCA
-
The Power Cost Adjustment mechanism, a procedure for accounting and rate recovery of certain power supply costs accepted by the utility commission in the state of Idaho
PGA
-
Purchased Gas Adjustment
PLP
-
Potentially liable party
PUD
-
Public Utility District
PURPA
-
The Public Utility Regulatory Policies Act of 1978, as amended
RCA
-
The Regulatory Commission of Alaska
RTO
-
Regional Transmission Organization
Spokane Energy
-
Spokane Energy, LLC, a special purpose limited liability company and all of its membership capital is owned by Avista Corp.
Spokane River Project
-
The five hydroelectric plants operating under one FERC license on the Spokane River (Long Lake, Nine Mile, Upper Falls, Monroe Street and Post Falls)
Therm
-
Unit of measurement for natural gas; a therm is equal to approximately one hundred cubic feet (volume) or 100,000 BTUs (energy)
UTC
-
Washington Utilities and Transportation Commission
Watt
-
Unit of measurement for electricity; a watt is equal to the rate of work represented by a current of one ampere under a pressure of one volt

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AVISTA CORPORATION



Forward-Looking Statements
From time to time, we make forward-looking statements such as statements regarding projected or future:
financial performance;
cash flows;
capital expenditures;
dividends;
capital structure;
other financial items;
strategic goals and objectives;
business environment; and
plans for operations.
These statements have underlying assumptions (many of which are based, in turn, upon further assumptions). Such statements are made both in our reports filed under the Securities Exchange Act of 1934, as amended (including this Annual Report on Form 10-K), and elsewhere. Forward-looking statements are all statements except those of historical fact including, without limitation, those that are identified by the use of words that include “will,” “may,” “could,” “should,” “intends,” “plans,” “seeks,” “anticipates,” “estimates,” “expects,” “forecasts,” “projects,” “predicts,” and similar expressions.
Forward-looking statements (including those made in this Annual Report on Form 10-K) are subject to a variety of risks and uncertainties and other factors. Most of these factors are beyond our control and may have a significant effect on our operations, results of operations, financial condition or cash flows, which could cause actual results to differ materially from those anticipated in our statements. Such risks, uncertainties and other factors include, among others:
weather conditions (temperatures, precipitation levels and wind patterns) which affect energy demand and electric generation, including the effect of precipitation and temperature on hydroelectric resources, the effect of wind patterns on wind-generated power, weather-sensitive customer demand, and similar impacts on supply and demand in the wholesale energy markets;
state and federal regulatory decisions that affect our ability to recover costs and earn a reasonable return including, but not limited to, disallowance or delay in the recovery of capital investments and operating costs and discretion over allowed return on investment;
changes in wholesale energy prices that can affect operating income, cash requirements to purchase electricity and natural gas, value received for wholesale sales, collateral required of us by counterparties on wholesale energy transactions and credit risk to us from such transactions, and the market value of derivative assets and liabilities;
economic conditions in our service areas, including the economy's effects on customer demand for utility services;
declining energy demand related to customer energy efficiency and/or conservation measures;
our ability to obtain financing through the issuance of debt and/or equity securities, which can be affected by various factors including our credit ratings, interest rates and other capital market conditions and the global economy;
the potential effects of legislation or administrative rulemaking, including possible effects on our generating resources of restrictions on greenhouse gas emissions to mitigate concerns over global climate changes;
political pressures or regulatory practices that could constrain or place additional cost burdens on our energy supply sources, such as campaigns to halt coal-fired power generation and opposition to other thermal generation, wind turbines or hydroelectric facilities;
changes in actuarial assumptions, interest rates and the actual return on plan assets for our pension and other postretirement benefit plans, which can affect future funding obligations, pension and other postretirement benefit expense and the related liabilities;
volatility and illiquidity in wholesale energy markets, including the availability of willing buyers and sellers, and prices of purchased energy and demand for energy sales including related energy commodity derivative instruments that we rely upon to hedge our wholesale energy risks;

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AVISTA CORPORATION



the outcome of pending regulatory and legal proceedings arising out of the “western energy crisis” of 2000 and 2001, including possible refunds;
the outcome of legal proceedings and other contingencies;
changes in environmental and endangered species laws, regulations, decisions and policies, including present and potential environmental remediation costs and our compliance with these matters;
wholesale and retail competition including alternative energy sources, growth in customer-owned power resource technologies that displace utility-supplied energy or that may be sold back to the utility, and alternative energy suppliers and delivery arrangements;
growth or decay of our customer base and the extent that new uses for our services may materialize or existing uses may decline;
the ability to comply with the terms of the licenses for our hydroelectric generating facilities at cost-effective levels;
severe weather or natural disasters that can disrupt energy generation, transmission and distribution, as well as the availability and costs of materials, equipment, supplies and support services;
explosions, fires, accidents, mechanical breakdowns, or other incidents that may impair assets and may disrupt operations of any of our generation facilities, transmission and distribution systems or other operations;
public injuries or damage arising from or allegedly arising from our operations;
blackouts or disruptions of interconnected transmission systems (the regional power grid);
disruption to information systems, automated controls and other technologies that we rely on for our operations, communications and customer service;
terrorist attacks, cyber attacks or other malicious acts that may disrupt or cause damage to our utility assets or to the national economy in general, including any effects of terrorism, cyber attacks or vandalism that damage or disrupt information technology systems;
cyber attacks or other potential lapses that result in unauthorized disclosure of private information, which could result in liabilities against us, costs to investigate, remediate and defend, and damage to our reputation;
delays or changes in construction costs, and/or our ability to obtain required permits and materials for present or prospective facilities;
changes in the costs to implement new information technology systems and/or obstacles that impede our ability to complete such projects timely and effectively;
changes in the long-term global and Pacific Northwest climates, which can affect, among other things, customer demand patterns and the volume and timing of streamflows to our hydroelectric resources;
changes in industrial, commercial and residential growth and demographic patterns in our service territory or changes in demand by significant customers;
the loss of key suppliers for materials or services or disruptions to the supply chain;
default or nonperformance on the part of any parties from which we purchase and/or sell capacity or energy;
deterioration in the creditworthiness of our customers;
potential decline in our credit ratings, with effects including impeded access to capital markets, higher interest costs, and restrictive covenants in our financing arrangements and wholesale energy contracts;
increasing health care costs and the resulting effect on employee injury costs and health insurance provided to our employees and retirees;
increasing costs of insurance, more restrictive coverage terms and our ability to obtain insurance;
work force issues, including changes in collective bargaining unit agreements, strikes, work stoppages, the loss of key executives, availability of workers in a variety of skill areas, and our ability to recruit and retain employees;
the potential effects of negative publicity regarding business practices, whether true or not, which could result in litigation or a decline in our common stock price;
changes in technologies, possibly making some of the current technology obsolete;

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AVISTA CORPORATION



changes in tax rates and/or policies;
changes in interest rates that affect borrowing costs, our ability to effectively hedge interest rates for anticipated debt issuances, variable interest rate borrowing and the extent that we recover interest costs through utility operations;
changes in the payment acceptance policies of Ecova’s client vendors that could reduce operating revenues;
potential difficulties in integrating acquired operations and in realizing expected opportunities, diversions of management resources and losses of key employees, challenges with respect to operating new businesses and other unanticipated risks and liabilities; and
changes in our strategic business plans, which may be affected by any or all of the foregoing, including the entry into new businesses and/or the exit from existing businesses and the extent of our business development efforts where potential future business is uncertain.
Our expectations, beliefs and projections are expressed in good faith. We believe they are reasonable based on, without limitation, an examination of historical operating trends, our records and other information available from third parties. However, there can be no assurance that our expectations, beliefs or projections will be achieved or accomplished. Furthermore, any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which such statement is made or to reflect the occurrence of unanticipated events. New risks, uncertainties and other factors emerge from time to time, and it is not possible for us to predict all such factors, nor can we assess the effect of each such factor on our business or the extent that any such factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statement.
Available Information
Our Web site address is www.avistacorp.com. We make annual, quarterly and current reports available at our Web site as soon as practicable after electronically filing these reports with the Securities and Exchange Commission. Information contained on our Web site is not part of this report. 

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AVISTA CORPORATION



PART I
Item 1. Business
Company Overview
Avista Corporation (Avista Corp. or the Company), incorporated in the territory of Washington in 1889, is an energy company engaged in the generation, transmission and distribution of electricity and the distribution of natural gas, as well as other energy-related businesses. As of December 31, 2013, we employed 1,643 people in our utility operations and 1,667 people in our subsidiary businesses. Our corporate headquarters are in Spokane, Washington, the second-largest city in Washington. Spokane serves as the business, transportation, medical, industrial and cultural hub of the Inland Northwest region (eastern Washington and northern Idaho). Regional services include government and higher education, medical services, retail trade and finance. The Inland Northwest also coincides closely with our utility service area in Washington and Idaho. Our gas utility operations also include separate service areas in parts of Oregon.
We have two reportable business segments as follows:
Avista Utilities – an operating division of Avista Corp. that comprises our regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas serving electric and gas customers in eastern Washington and northern Idaho and gas customers in parts of Oregon. The utility also engages in wholesale purchases and sales of electricity and natural gas.
Ecova – an indirect subsidiary of Avista Corp. (80.2 percent owned as of December 31, 2013) that provides energy efficiency and cost management programs and services for multi-site customers and utilities throughout North America. Ecova's service lines include expense management services for utility and telecom needs as well as strategic energy management and efficiency services that include procurement, conservation, performance reporting, financial planning, facility optimization and continuous monitoring, and energy efficiency program management for commercial enterprises and utilities.
We have other businesses, including a sheet metal fabrication business, emerging technology venture fund investments and commercial real estate investments, as well as Spokane Energy, LLC (Spokane Energy). These activities do not represent a reportable business segment and are conducted by various indirect subsidiaries of Avista Corp.
Ecova and various other companies are subsidiaries of Avista Capital, Inc. (Avista Capital) which is a direct, wholly owned subsidiary of Avista Corp. Total Avista Corp. shareholders’ equity was $1,298.3 million as of December 31, 2013, of which $112.2 million represented our investment in Avista Capital. Additionally, Ecova represents $81.9 million of our investment in Avista Capital.
See “Item 6. Selected Financial Data” and “Note 23 of the Notes to Consolidated Financial Statements” for information with respect to the operating performance of each business segment (and other subsidiaries).

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AVISTA CORPORATION



Avista Utilities
General
Through our regulated utility operations, we generate, transmit and distribute electricity and distribute natural gas. Retail electric and natural gas customers include residential, commercial and industrial classifications. We also engage in wholesale purchases and sales of electricity and natural gas as an integral part of energy resource management and our load-serving obligation.
Our utility provides electric distribution and transmission, as well as natural gas distribution, services in parts of eastern Washington and northern Idaho. We also provide natural gas distribution service in parts of northeastern and southwestern Oregon. At the end of 2013, we supplied retail electric service to 366,000 customers and retail natural gas service to 326,000 customers across our entire service territory. Our service territory covers 30,000 square miles with a population of 1.6 million. Certain of our generating facilities are located in Montana, and we supply electricity to a small number of customers in Montana, most of whom are employees who operate one of such facilities. See “Item 2. Properties” for further information on our utility assets. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Economic Conditions and Utility Load Growth” for information on economic conditions in our service territory.
Electric Operations
In addition to providing electric distribution and transmission services, we generate electricity from facilities that we own and we purchase capacity, energy and fuel for generation under long-term and short-term contracts. We also sell electric capacity and energy, as well as surplus fuel in the wholesale market in connection with our resource optimization activities as described below.
As part of our resource procurement and management operations in the electric business, we engage in an ongoing process of resource optimization, which involves the economic selection from available energy resources to serve our load obligations and the use of these resources to capture available economic value. We transact business in the wholesale markets by selling and purchasing electric capacity and energy, fuel for electric generation, and derivative instruments related to capacity, energy, transport and fuel. Such transactions are part of the process of matching resources with our load obligations and hedging the related financial risks. These transactions range from terms of intra-hour up to multiple years. We make continuing projections of:
electric loads at various points in time (ranging from intra-hour to multiple years) based on, among other things, estimates of customer usage and weather, historical data and contract terms, and
resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of streamflows, availability of generating units, historic and forward market information, contract terms, and experience.
On the basis of these projections, we make purchases and sales of electric capacity and energy, fuel for electric generation, and related derivative instruments to match expected resources to expected electric load requirements and reduce our exposure to electricity (or fuel) market price changes. Resource optimization involves generating plant dispatch and scheduling available resources and also includes transactions such as:
purchasing fuel for generation,
when economical, selling fuel and substituting wholesale electric purchases, and
other wholesale transactions to capture the value of generation and transmission resources and fuel delivery (transport) capacity contracts.
Our optimization process includes entering into hedging transactions to manage risks. Transactions include both physical energy contracts and related derivative instruments.
Our generation assets are interconnected through the regional transmission system and are operated on a coordinated basis to enhance load-serving capability and reliability. We provide transmission and ancillary services in eastern Washington, northern Idaho and western Montana. Transmission revenues were $26.5 million in 2013, $12.7 million in 2012 and $13.8 million in 2011. Transmission revenues for 2013 include $11.7 million from the BPA for past use of our electric transmission system.
Electric Requirements
Our peak electric native load requirement for 2013 occurred on December 8, 2013 at which time our total obligation was 2,223 MW consisting of:

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AVISTA CORPORATION



native load of 1,669 MW,
long-term wholesale obligations of 223 MW, and
short-term wholesale obligations of 331 MW.
At that time our maximum resource capacity available was 2,767 MW, which included:
company-owned or controlled electric generation of 1,703 MW,
long-term hydroelectric contracts with certain Public Utility Districts (PUDs) of 156 MW,
long-term thermal generation contract with Lancaster Plant of 281 MW,
other long-term wholesale contracts of 151 MW, and
short-term wholesale purchases of 476 MW.
Electric Resources
We have a diverse electric resource mix of Company-owned and contracted hydroelectric projects, thermal generating facilities, wind generation facilities, and power purchases and exchanges.
At the end of 2013, our Company-owned facilities had a total net capability of 1,844 MW, of which 55 percent was hydroelectric and 45 percent was thermal. See “Item 2. Properties” for detailed information on generating facilities.
Hydroelectric Resources We own and operate six hydroelectric projects on the Spokane River and two hydroelectric projects on the Clark Fork River. Hydroelectric generation is our lowest cost source per megawatt-hour (MWh) of electricity and the availability of hydroelectric generation has a significant effect on total power supply costs. Under normal streamflow and operating conditions, we estimate that we would be able to meet approximately one-half of our total average electric requirements (both retail and long-term wholesale) with the combination of our hydroelectric generation and long-term hydroelectric purchase contracts with certain PUDs in the state of Washington. Our estimate of normal annual hydroelectric generation for 2014 (including resources purchased under long-term hydroelectric contracts with certain PUDs) is 533 average megawatts (aMW) (or 4.7 million MWhs). Hydroelectric resources provided 527 aMW for 2013, 583 aMW for 2012 and 637 aMW for 2011.
The following table shows our hydroelectric generation (in thousands of MWhs) during the year ended December 31:
 
2013
 
2012
 
2011
Noxon Rapids
1,581

 
1,823

 
2,110

Cabinet Gorge
1,042

 
1,199

 
1,292

Post Falls
85

 
83

 
90

Upper Falls
68

 
60

 
73

Monroe Street
105

 
102

 
110

Nine Mile
83

 
106

 
90

Long Lake
505

 
513

 
556

Little Falls
177

 
202

 
213

Total company-owned hydroelectric generation
3,646

 
4,088

 
4,534

Long-term hydroelectric contracts with PUDs
970

 
1,022

 
1,047

Total hydroelectric generation
4,616

 
5,110

 
5,581

Normal hydroelectric generation (1)
4,678

 
4,761

 
4,520

Percentage of normal
99
%
 
107
%
 
123
%
(1)
Normal hydroelectric generation is determined by applying an upstream regulation calculation to median natural water flow information. Natural water flow is the flow of the rivers without the influence of dams, whereas regulated water flow takes into account any water flows changes from upstream dams due to releasing or holding back water. The calculation of normal varies annually due to the timing of upstream dam regulation throughout the year.
Thermal Resources We own:
the combined cycle combustion turbine (CT) natural gas-fired Coyote Springs 2 Generation Project (Coyote Springs 2) located near Boardman, Oregon,

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a 15 percent interest in a twin-unit, coal-fired boiler generating facility, the Colstrip 3 & 4 Generating Project (Colstrip) in southeastern Montana,
a wood waste-fired boiler generating facility known as the Kettle Falls Generating Station (Kettle Falls GS) in northeastern Washington,
a two-unit natural gas-fired CT generating facility, located in northeastern Spokane (Northeast CT),
a two-unit natural gas-fired CT generating facility in northern Idaho (Rathdrum CT), and
two small natural gas-fired generating facilities (Boulder Park and Kettle Falls CT).
Coyote Springs 2, which is operated by Portland General Electric Company, is supplied with natural gas under both term contracts and spot market purchases, including transportation agreements with bilateral renewal rights.
Colstrip, which is operated by PPL Montana, LLC, is supplied with fuel from adjacent coal reserves under coal supply and transportation agreements in effect through 2019.
The primary fuel for the Kettle Falls GS is wood waste generated as a by-product and delivered by trucks from forest industry operations within 100 miles of the plant. A combination of long-term contracts and spot purchases has provided, and is expected to meet, fuel requirements for the Kettle Falls GS.
The Northeast CT, Rathdrum CT, Boulder Park and Kettle Falls CT generating units are primarily used to meet peaking electric requirements. We also operate these facilities when marginal costs are below prevailing wholesale electric prices. These generating facilities have access to natural gas supplies that are adequate to meet their respective operating needs.
See "Item 2 Properties - Avista Utilities - Generation Properties" for the nameplate rating and present generating capabilities of the above thermal resources.
 
The following table shows our thermal generation (in thousands of MWhs) during the year ended December 31:
 
2013
 
2012
 
2011
Coyote Springs 2
1,796

 
1,142

 
705

Colstrip
1,227

 
1,499

 
1,433

Kettle Falls GS
294

 
209

 
291

Northeast CT and Rathdrum CT
34

 
7

 
8

Boulder Park and Kettle Falls CT
32

 
7

 
10

Total company-owned thermal generation
3,383

 
2,864

 
2,447

Long-term contract with Lancaster Plant
1,656

 
1,208

 
835

Total thermal generation
5,039

 
4,072

 
3,282

Lancaster Plant Power Purchase Agreement The Lancaster Plant is a 270 MW natural gas-fired combined cycle combustion turbine plant located in Idaho, owned by an unrelated third-party. All of the output from the Lancaster Plant is contracted to us through 2026 under a power purchase agreement (PPA).
Palouse Wind PPA Palouse Wind is a wind generation project developed by Palouse Wind, LLC (Palouse Wind), an affiliate of First Wind Holdings, LLC, and located in Whitman County, Washington. In June 2011, we entered into a 30-year PPA with Palouse Wind to acquire all of the power and renewable attributes produced by the project at a fixed price per MWh with a fixed escalation of the price over the term of the agreement. The project has a nameplate capacity of approximately 105 MW and is expected to produce approximately 40 aMW. Deliveries from the project began during the fourth quarter of 2012. Generation from Palouse Wind was 297,027 MWhs in 2013 and 61,450 MWhs in 2012. We have an annual option to purchase the wind project following the 10th anniversary of its December 2012 commercial operation date. The purchase price per the PPA is a fixed price per KW of in-service capacity with a fixed decline in the price per KW over the remaining 20 year term of the agreement.
Other Purchases, Exchanges and Sales In addition to the resources described above, we purchase and sell power under various long-term contracts and we also enter into short-term purchases and sales. Further, pursuant to the Public Utility Regulatory Policies Act of 1978 (PURPA), as amended, we are required to purchase generation from qualifying facilities. This includes, among other resources, hydroelectric projects, cogeneration projects and wind generation projects at rates approved by the Washington Utilities and Transportation Commission (UTC) and the Idaho Public Utilities Commission (IPUC). Existing PURPA contracts expire at various times through 2022.

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See “Avista Utilities Operating Statistics – Electric Operations – Electric Energy Resources” for annual quantities of purchased power, wholesale power sales and power from exchanges in 2013, 2012 and 2011. See “Electric Operations” for additional information with respect to the use of wholesale purchases and sales as part of our resource optimization process and also see "Future Resource Needs" for the magnitude of these power purchase and sales contracts in future periods.
Hydroelectric Licensing
We are a licensee under the Federal Power Act as administered by the FERC, which includes regulation of hydroelectric generation resources. Excluding the Little Falls Hydroelectric Generating Project, our other seven hydroelectric plants are regulated by the FERC through two project licenses. The licensed projects are subject to the provisions of Part I of the Federal Power Act. These provisions include payment for headwater benefits, condemnation of licensed projects upon payment of just compensation, and take-over of such projects after the expiration of the license upon payment of the lesser of “net investment” or “fair value” of the project, in either case, plus severance damages.
The Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) and the Noxon Rapids Hydroelectric Generating Project (Noxon Rapids) are under one 45-year FERC license issued in March 2001. See “Cabinet Gorge Total Dissolved Gas Abatement Plan” in “Note 20 of the Notes to Consolidated Financial Statements” for discussion of dissolved atmospheric gas levels that exceed state of Idaho and federal water quality standards downstream of Cabinet Gorge during periods when we must divert excess river flows over the spillway and our mitigation plans and efforts.
Five of our six hydroelectric projects on the Spokane River (Long Lake, Nine Mile, Upper Falls, Monroe Street, and Post Falls) are under one 50-year FERC license issued in June 2009 and are referred to collectively as the Spokane River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. For further information see “Spokane River Licensing” in “Note 20 of the Notes to Consolidated Financial Statements.”
Future Resource Needs
We have operational strategies to provide sufficient resources to meet our energy requirements under a range of operating conditions. These operational strategies consider the amount of energy needed, which varies widely because of the factors that influence demand over intra-hour, hourly, daily, monthly and annual durations. Our average hourly load was 1,086 aMW in 2013, 1,075 aMW in 2012 and 1,096 aMW in 2011. The following is a forecast of our average annual energy requirements and resources for 2014 through 2017:
Forecasted Electric Energy Requirements and Resources
(aMW)
 
2014
 
2015
 
2016
 
2017
Requirements:
 
 
 
 
 
 
 
System load (1)
1,050

 
1,057

 
1,064

 
1,072

Contracts for power sales (2)
115

 
63

 
63

 
12

Total requirements
1,165

 
1,120

 
1,127

 
1,084

Resources:
 
 
 
 
 
 
 
Company-owned and contract hydro generation (3)
528

 
501

 
506

 
506

Company-owned and contract thermal generation (4)
723

 
725

 
718

 
715

Other contracts for power purchases
170

 
169

 
168

 
116

Total resources
1,421

 
1,395

 
1,392

 
1,337

Surplus resources
256

 
275

 
265

 
253

Additional available energy (5)
153

 
139

 
154

 
153

Total surplus resources
409

 
414

 
419

 
406

 
(1)
Beginning on June 30, 2013 a large industrial customer began generating electricity to meet a portion of its own load rather than selling the generation to Avista. The full impact of this load change culminates in 2014 when load is reduced for 12 calendar months. See Item 7. Management's Discussion and Analysis - "Customer Contract Renewal" for further discussion of this industrial customer.
(2)
The contracts for power sales decrease in 2015 and again in 2017 due to certain contracts expiring at the beginning of each of these years. We are currently evaluating the future plan for the additional resources made available due to the expiration of these contracts.
(3)
The forecast assumes near normal hydroelectric generation (decline in 2015 is due to changes in contracts with PUDs).

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(4)
Includes our long-term contract with the owner of the Lancaster Plant. Excludes Northeast CT and Rathdrum CT as these are considered peaking facilities and are generally not used to meet our base load requirements. We generally dispatch thermal resources when operating costs are lower than short-term wholesale market prices.
(5)
Northeast CT and Rathdrum CT. The combined maximum capacity of the Northeast CT and Rathdrum CT is 242 MW, with estimated available energy production as indicated for each year. The available energy from these resources decreases during 2015 due to Rathdrum CT being down for scheduled maintenance.
In August 2013, we filed our 2013 Electric Integrated Resource Plan (IRP) with the UTC and the IPUC. The IRP details projected growth in demand for energy and the new resources needed to serve customers over the next 20 years. We regard the IRP as a tool for resource evaluation, rather than an acquisition plan for a particular project.
Highlights of the 2013 IRP include:
In our IRP in 2011, we had certain recommendations for new renewable resources. These have been met with a 30-year PPA with Palouse Wind and the Kettle Falls GS being qualified as a renewable energy resource under the Washington state Energy Independence Act.
Load growth is expected to be approximately 1 percent, a decline from the growth of 1.6 percent forecasted in 2011. This delays the need for a new natural gas-fired resource by one year. The decrease in expected load growth is primarily due to energy efficiency programs (using less energy to perform activities) over the next 20 years. See "Item 7. Management Discussion and Analysis – Forecasted Customer and Load Growth and Economic Conditions and Utility Load Growth" for further discussion regarding utility customer growth, load growth, and the general economic conditions in our service territory.
Demand response (temporarily reducing the demand for energy) is included in the Preferred Resource Strategy for the first time and could provide 19 MW of peak energy reduction in the 2022 to 2027 time frame.
575 MW of additional natural gas-fired generation facilities are required between 2020 and 2033.
Transmission upgrades will be needed to deliver the energy from new generation resources to the distribution lines serving customers. We will continue to participate in regional efforts to expand the region’s transmission system.
We are required to file an IRP every two years with the next IRP expected to be filed during the third quarter of 2015. Our resource strategy may change from the 2013 IRP based on market, legislative and regulatory developments.
We are subject to the Washington state Energy Independence Act, which requires us to obtain a portion of our electricity from qualifying renewable resources or through purchase of renewable energy credits and acquiring all cost effective conservation measures. Future generation resource decisions will be impacted by legislation for restrictions on greenhouse gas emissions and renewable energy requirements.
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Issues and Other Contingencies” for information related to existing laws, as well as potential legislation that could influence our future electric resource mix.
Natural Gas Operations
General We provide natural gas distribution services to retail customers in parts of eastern Washington, northern Idaho, and northeastern and southwestern Oregon.
Market prices for natural gas, like other commodities, can be volatile. Our natural gas procurement strategy is to provide reliable supply to our customers with some level of price certainty. We procure natural gas from various supply basins and over varying time periods. The resulting portfolio is a diversified mix of spot market purchases and forward fixed price purchases, utilizing physical and financial derivative instruments. We also use natural gas storage to support high demand periods and to procure natural gas when prices may be lower. Securing prices throughout the year and even into subsequent years provides a level of price certainty and can mitigate price volatility to customers between years.
Weather is a key component of our natural gas customer load. This load is highly variable and daily natural gas loads can differ significantly from the monthly forecasted load projections. We make continuing projections of our natural gas loads and assess available natural gas resources. On the basis of these projections, we plan and execute a series of transactions to hedge a portion of our customer’s projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend for multiple years into the future with the highest volumes hedged for the current and most immediate

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upcoming natural gas operating year (November through October). We also leave a portion of our natural gas supply requirements unhedged for purchase in the short-term spot markets.
Our purchase of natural gas supply is governed by our procurement plan. This plan is reviewed and modified annually by an internal management group. The updated plan is presented and discussed with staff in all three state jurisdictions. Communication with staff does not constitute pre-approval; however, it provides transparency to our procurement practices and offers the staff and other stakeholders an opportunity to express concerns, ask questions and learn about the factors contributing to the plan’s development and subsequent execution. The plan is then presented to our Risk Management Committee (RMC) for approval. Once approval is received, the plan is implemented and monitored by our gas supply and risk management groups.
The plan’s ongoing progress is also presented to Washington and Idaho staff in semi-annual meetings, and in Oregon updates are given quarterly. Other stakeholders (Public Counsel, Citizen Utility Board) are also invited to participate. The RMC is provided with an update on plan results and changes in their monthly meetings. These activities provide transparency for the natural gas supply procurement plan. Any material changes to the plan are documented and communicated via email to RMC members.
As part of the process of balancing natural gas retail load requirements with resources, we engage in the wholesale purchase and sale of natural gas. We plan for sufficient natural gas delivery capacity to serve our retail customers for a theoretical peak day event. As such, we generally have more pipeline and storage capacity than what is needed during periods other than a peak day. We optimize our natural gas resources by using market opportunities to generate economic value that helps mitigate fixed costs. Wholesale sales are delivered through wholesale market facilities outside of our natural gas distribution system. Natural gas resource optimization activities include, but are not limited to:
wholesale market sales of surplus natural gas supplies,
purchases and sales of natural gas to optimize use of pipeline and storage capacity, and
participation in the transportation capacity release market.
We also provide distribution transportation service to qualified, large commercial and industrial natural gas customers who purchase natural gas through third-party marketers. For these customers, we receive their purchased natural gas from such third-party marketers into our distribution system and redeliver it to the customers’ premise.
Natural Gas Supply We purchase all of our natural gas in wholesale markets. We are connected to multiple supply basins in the western United States and Canada through firm capacity transportation rights on six different pipeline networks. Access to this diverse portfolio of natural gas resources allows us to make natural gas procurement decisions that benefit our natural gas customers. These interstate pipeline transportation rights provide the capacity to serve approximately 25 percent of peak natural gas customer demands from domestic sources, and 75 percent from Canadian sourced supply. Natural gas prices in the Pacific Northwest are affected by global energy markets, as well as supply and demand factors in other regions of the United States and Canada. Future prices and delivery constraints may cause our resource mix to vary.
Natural Gas Storage We own a one-third interest in the Jackson Prairie Natural Gas Storage Project (Jackson Prairie), an underground natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 11.5 million therms, with a total working natural gas capacity of 253 million therms. As an owner, our share is one-third of the peak day deliverability and total working capacity. We also contract for additional storage capacity and delivery at Jackson Prairie from Northwest Pipeline for a portion of their one-third share of the storage project.
Natural gas storage enables us to store gas in the summer when prices are traditionally lower and withdraw during higher priced winter months. It is also used as a variable peaking resource during cold weather events.
Natural Gas Pipeline Replacement In 2011 we began implementation of a plan to replace certain vintages of Aldyl A natural gas pipe within our distribution systems in Washington, Idaho, and Oregon. In early 2012, we released our protocol report to each state utility commission describing our Aldyl A natural gas pipe replacement plan across our natural gas system. Later in 2012, after technical workshops held by the UTC to gather perspectives on pipeline replacement programs, including the need for expedited cost recovery, the UTC required all natural gas utilities operating in Washington to file applicable replacement plans with the Commission. We subsequently filed our protocol report with the UTC proposing to replace our Aldyl A natural gas pipe across our three state jurisdictions over a 20-year period at a cost of approximately $10 million per year, indexed to inflation. Subsequent to this protocol report, during the third quarter of 2013, we revised our estimated replacement costs to approximately $16 million per year, indexed to inflation over a 20-year period. We expect to receive cost recovery for these capital expenditures from the three jurisdictions over the life of these assets.



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Regulatory Issues
General As a public utility, we are subject to regulation by state utility commissions for prices, accounting, the issuance of securities and other matters. The retail electric and natural gas operations are subject to the jurisdiction of the UTC, the IPUC, the Public Utility Commission of Oregon (OPUC), and the Public Service Commission of the State of Montana (MPSC). Approval of the issuance of securities is not required from the MPSC. We are also subject to the jurisdiction of the FERC for licensing of hydroelectric generation resources, and for electric transmission services and wholesale sales.
Our rates for retail electric and natural gas services (other than specially negotiated retail rates for industrial or large commercial customers, which are subject to regulatory review and approval) are generally determined on a “cost of service” basis. 
 
Rates are designed to provide an opportunity for us to recover allowable operating expenses and earn a reasonable return on “rate base.” Rate base is generally determined by reference to the original cost (net of accumulated depreciation) of utility plant in service, subject to various adjustments for deferred taxes and other items. Over time, rate base is increased by additions to utility plant in service and reduced by depreciation and retirement of utility plant and write-offs as authorized by the utility commissions. Our operating expenses and rate base are allocated or directly assigned among five regulatory jurisdictions: electric in Washington and Idaho, and natural gas in Washington, Idaho and Oregon. In general, a request for new retail rates in Washington and Idaho is made on the basis of net investment, operating expenses and revenues for a test year that ended prior to the date of the request, plus certain adjustments designed to reflect the expected revenues, expenses and net investment during the period new retail rates will be in effect. The retail rates approved by the state commissions in a rate proceeding may not provide sufficient revenues to provide recovery of costs and a reasonable return on investment for a number of reasons, including but not limited to, unexpected changes in revenues, expenses and investment following the time new retail rates are requested in the rate proceeding, and exclusion of certain costs and investment by the commission from the rate making process. Oregon currently allows the use of a forecasted test year to establish retail rates for the rate year.
Our rates for wholesale electric and natural gas transmission services are based on either “cost of service” principles or market-based rates as set forth by the FERC. See “Notes 1 and 22 of the Notes to Consolidated Financial Statements” for additional information about regulation, depreciation and deferred income taxes.
General Rate Cases We regularly review the need for electric and natural gas rate changes in each state in which we provide service. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – General Rate Cases” for information on general rate case activity.
Power Cost Deferrals We defer the recognition in the income statement of certain power supply costs that vary from the level currently recovered from our retail customers as authorized by the UTC and the IPUC. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – Power Cost Deferrals and Recovery Mechanisms” and “Note 22 of the Notes to Consolidated Financial Statements” for detailed information on power cost deferrals and recovery mechanisms in Washington and Idaho.
Purchased Gas Adjustment (PGA) Under established regulatory practices in each state, we are allowed to adjust natural gas rates periodically (with regulatory approval) to reflect increases or decreases in the cost of natural gas purchased. Differences between actual natural gas costs and the natural gas costs included in retail rates are deferred during the period the differences are incurred. During the subsequent period when regulators approve inclusion of the cost changes in rates, any amounts that were previously deferred are charged or credited to expense. We typically propose such PGAs at least once per year. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Avista Utilities – Regulatory Matters – Purchased Gas Adjustments” and “Note 22 of the Notes to Consolidated Financial Statements” for detailed information on natural gas cost deferrals and recovery mechanisms in Washington, Idaho and Oregon.
Federal Laws Related to Wholesale Competition
Federal law promotes practices that open the electric wholesale energy market to competition. The FERC requires electric utilities to transmit power and energy to or for wholesale purchasers and sellers, and requires electric utilities to enhance or construct transmission facilities to create additional transmission capacity for the purpose of providing these services. Public utilities (through subsidiaries or affiliates) and other entities may participate in the development of independent electric generating plants for sales to wholesale customers.
Public utilities operating under the Federal Power Act are required to provide open and non-discriminatory access to their transmission systems to third parties and establish an Open Access Same-Time Information System to provide an electronic means by which transmission customers can obtain information about available transmission capacity and purchase transmission access. The FERC also requires each public utility subject to the rules to operate its transmission and wholesale

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power merchant operating functions separately and to comply with standards of conduct designed to ensure that all wholesale users, including the public utility’s power merchant operations, have equal access to the public utility’s transmission system. Our compliance with these standards has not had any substantive impact on the operation, maintenance and marketing of our transmission system or our ability to provide service to customers.
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Competition” for further information.
Regional Transmission Organizations
Beginning with FERC Order No. 888 and continuing with subsequent rulemakings and policies, the FERC has encouraged better coordination and operational consistency aimed to capture efficiencies that might otherwise be gained through the formation of a Regional Transmission Organization (RTO) or an independent system operator (ISO).
We meet our FERC requirements to coordinate transmission planning activities with other regional entities through ColumbiaGrid. ColumbiaGrid is a Washington nonprofit membership corporation with an independent board formed to improve the operational efficiency, reliability, and planned expansion of the transmission grid in the Pacific Northwest. We became a member of ColumbiaGrid in 2006 during its formation. ColumbiaGrid is not an ISO, but performs only those functions that its members request, as set forth in specific agreements. Currently, ColumbiaGrid fills the role of facilitating our regional transmission planning as required in Order No. 1000 and other clarifying Orders. ColumbiaGrid and its members also work with other western organizations to address transmission planning, including WestConnect and the Northern Tier Transmission Group (NTTG). In 2011, we became a registered Planning Participant of the NTTG. We will continue to assess the benefits of entering into other functional agreements with ColumbiaGrid and/or participating in other forums to attain operational efficiencies and to meet FERC policy objectives.
Reliability Standards
Among its other provisions, the U.S. Energy Policy Act provides for the implementation of mandatory reliability standards and authorizes the FERC to assess penalties for non-compliance with these standards and other FERC regulations.
The FERC certified the North American Electricity Reliability Corporation (NERC) as the single Electric Reliability Organization authorized to establish and enforce reliability standards and delegate authority to regional entities for the purpose of establishing and enforcing reliability standards. The FERC has approved the NERC Reliability Standards, including western region standards, making up the set of legally enforceable standards for the United States bulk electric system. The first of these reliability standards became effective in June 2007. We are required to self-certify our compliance with these standards on an annual basis and undergo regularly scheduled periodic reviews by the NERC and its regional entity, the Western Electricity Coordinating Council (WECC). Our failure to comply with these standards could result in financial penalties of up to $1 million per day per violation. Annual self-certification and audit processes to date have demonstrated our substantial compliance with these standards. Requirements relating to cyber security are continually evolving. Our compliance with the upcoming version 5 of the NERC's Critical Infrastructure Protection standard is driving several physical and electronic security initiatives in our control centers, generating stations and substations. We do not expect the costs of the physical and electronic securities initiatives to have a material impact to our financial results.

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AVISTA UTILITIES ELECTRIC OPERATING STATISTICS
 
 
Years Ended December 31,
 
2013
 
2012
 
2011
ELECTRIC OPERATIONS
 
 
 
 
 
OPERATING REVENUES (Dollars in Thousands):
 
 
 
 
 
Residential
$
331,867

 
$
315,137

 
$
324,835

Commercial
289,604

 
286,568

 
280,139

Industrial
113,632

 
119,589

 
122,560

Public street and highway lighting
7,267

 
7,240

 
6,941

Total retail
742,370

 
728,534

 
734,475

Wholesale
127,556

 
102,736

 
78,305

Sales of fuel
126,657

 
115,835

 
153,470

Other
36,071

 
21,067

 
21,937

Provision for refunds (1)
(2,048
)
 

 

Total electric operating revenues
$
1,030,606

 
$
968,172

 
$
988,187

ENERGY SALES (Thousands of MWhs):
 
 
 
 
 
Residential
3,745

 
3,608

 
3,728

Commercial
3,147

 
3,127

 
3,122

Industrial
1,979

 
2,100

 
2,147

Public street and highway lighting
26

 
26

 
26

Total retail
8,897

 
8,861

 
9,023

Wholesale
3,874

 
3,733

 
2,796

Total electric energy sales
12,771

 
12,594

 
11,819

ENERGY RESOURCES (Thousands of MWhs):
 
 
 
 
 
Hydro generation (from Company facilities)
3,646

 
4,088

 
4,534

Thermal generation (from Company facilities)
3,383

 
2,864

 
2,447

Purchased power - hydro generation from long-term contracts with PUDs
970

 
1,022

 
1,047

Purchased power - thermal generation from long-term contracts with Lancaster plant
1,656

 
1,208

 
835

Purchased power - wind generation from long-term contracts with Palouse Wind
297

 
61

 

Purchased power - wholesale
3,452

 
3,995

 
3,553

Power exchanges
(20
)
 
(10
)
 
(24
)
Total power resources
13,384

 
13,228

 
12,392

Energy losses and Company use
(613
)
 
(634
)
 
(573
)
Total energy resources (net of losses)
12,771

 
12,594

 
11,819

NUMBER OF RETAIL CUSTOMERS (Average for Period):
 
 
 
 
 
Residential
321,098

 
318,692

 
316,762

Commercial
40,202

 
39,869

 
39,618

Industrial
1,386

 
1,395

 
1,380

Public street and highway lighting
527

 
503

 
455

Total electric retail customers
363,213

 
360,459

 
358,215

RESIDENTIAL SERVICE AVERAGES:
 
 
 
 
 
Annual use per customer (KWh)
11,664

 
11,323

 
11,769

Revenue per KWh (in cents)
8.86

 
8.73

 
8.71

Annual revenue per customer
$
1,033.54

 
$
988.84

 
$
1,025.48

AVERAGE HOURLY LOAD (aMW)
1,086

 
1,075

 
1,096



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AVISTA UTILITIES ELECTRIC OPERATING STATISTICS
 
Years Ended December 31,
 
2013
 
2012
 
2011
REQUIREMENTS AND RESOURCE AVAILABILITY at time of system peak (MW):
 
 
 
 
 
Total requirements (winter):
 
 
 
 
 
Retail native load
1,669

 
1,554

 
1,669

Wholesale obligations
554

 
637

 
712

Total requirements (winter)
2,223

 
2,191

 
2,381

Total resource availability (winter)
2,767

 
2,618

 
2,923

Total requirements (summer):
 
 
 
 
 
Retail native load
1,577

 
1,579

 
1,535

Wholesale obligations
569

 
906

 
472

Total requirements (summer)
2,146

 
2,485

 
2,007

Total resource availability (summer)
2,813

 
3,060

 
2,370

COOLING DEGREE DAYS: (2)
 
 
 
 
 
Spokane, WA
 
 
 
 
 
Actual
709

 
535

 
426

30-year average (4)
394

 
434

 
434

% of average
180
%
 
123
%
 
98
%
HEATING DEGREE DAYS: (3)
 
 
 
 
 
Spokane, WA
 
 
 
 
 
Actual
6,683

 
6,256

 
6,861

30-year average (4)
6,780

 
6,676

 
6,647

% of average
99
%
 
94
%
 
103
%

(1)
This provision for refunds is specifically related to the Idaho general rate case which was settled in March 2013. See "Item 7. Management's Discussion and Analysis - Idaho General Rate Cases" for further discussion of this provision.
(2)
Cooling degree days are the measure of the warmness of weather experienced, based on the extent to which the average of high and low temperatures for a day exceeds 65 degrees Fahrenheit (annual degree days above historic indicate warmer than average temperatures).
(3)
Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).
(4)
The 30-year average heating and cooling degree days fluctuated in 2013 due to a change in our methodology for calculating the amount. In 2013, we have switched to a rolling 30-year average whereas in prior years we only received updated 30-year average data on a periodic basis.

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AVISTA UTILITIES NATURAL GAS OPERATING STATISTICS
 
 
Years Ended December 31,
 
2013
 
2012
 
2011
NATURAL GAS OPERATIONS
 
 
 
 
 
OPERATING REVENUES (Dollars in Thousands):
 
 
 
 
 
Residential
$
206,330

 
$
196,719

 
$
219,557

Commercial
102,225

 
98,994

 
111,964

Interruptible
2,681

 
2,232

 
2,519

Industrial
3,599

 
3,635

 
4,180

Total retail
314,835

 
301,580

 
338,220

Wholesale
194,717

 
158,631

 
195,882

Transportation
7,576

 
7,032

 
6,709

Other
8,573

 
6,930

 
7,414

Provision for refunds (1)
(442
)
 

 

Total natural gas operating revenues
$
525,259

 
$
474,173

 
$
548,225

THERMS DELIVERED (Thousands of Therms):
 
 
 
 
 
Residential
204,711

 
189,152

 
207,202

Commercial
122,245

 
115,083

 
125,344

Interruptible
5,694

 
4,363

 
4,503

Industrial
5,181

 
5,073

 
5,654

Total retail
337,831

 
313,671

 
342,703

Wholesale
524,818

 
586,193

 
510,755

Transportation
159,976

 
154,704

 
152,515

Interdepartmental and Company use
418

 
381

 
440

Total therms delivered
1,023,043

 
1,054,949

 
1,006,413

SOURCES OF NATURAL GAS DELIVERED (Thousands of Therms):
 
 
 
 
 
Purchases
834,068

 
919,684

 
877,290

Storage - injections
(97,338
)
 
(105,904
)
 
(109,782
)
Storage - withdrawals
129,006

 
93,850

 
94,504

Natural gas for transportation
159,976

 
154,704

 
152,515

Distribution system losses
(2,669
)
 
(7,385
)
 
(8,114
)
Total natural gas delivered
1,023,043

 
1,054,949

 
1,006,413

NUMBER OF RETAIL CUSTOMERS (Average for Period):
 
 
 
 
 
Residential
288,708

 
286,522

 
284,504

Commercial
33,932

 
33,763

 
33,540

Interruptible
38

 
38

 
38

Industrial
259

 
263

 
255

Total natural gas retail customers
322,937

 
320,586

 
318,337

RESIDENTIAL SERVICE AVERAGES:
 
 
 
 
 
Annual use per customer (therms)
709

 
660

 
728

Revenue per therm (in dollars)
$
1.01

 
$
1.04

 
$
1.06

Annual revenue per customer
$
714.67

 
$
686.57

 
$
771.72


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AVISTA UTILITIES NATURAL GAS OPERATING STATISTICS
 
Years Ended December 31,
 
2013
 
2012
 
2011
HEATING DEGREE DAYS: (2)
 
 
 
 
 
Spokane, WA
 
 
 
 
 
Actual
6,683

 
6,256

 
6,861

30-year average (3)
6,780

 
6,676

 
6,647

% of average
99
%
 
94
%
 
103
%
Medford, OR
 
 
 
 
 
Actual
4,576

 
4,182

 
4,634

30-year average (3)
4,539

 
4,422

 
4,402

% of average
101
%
 
95
%
 
105
%

(1)
This provision for rate refunds is specifically related to the Idaho general rate case which was settled in March 2013. See "Item 7. Management's Discussion and Analysis - Idaho General Rate Cases" for further discussion of this provision.
(2)
Heating degree days are the measure of the coldness of weather experienced, based on the extent to which the average of high and low temperatures for a day falls below 65 degrees Fahrenheit (annual degree days below historic indicate warmer than average temperatures).
(3)
The 30-year average heating degree days fluctuated in 2013 due to a change in our methodology for calculating the amount. In 2013, we have switched to a rolling 30-year average whereas in prior years we only received updated 30-year average data on a periodic basis.
Ecova
Ecova provides sustainable utility expense management and energy management solutions to multi-site companies across North America. Ecova’s invoice processing, auditing and payment services, coupled with energy procurement, comprehensive reporting and advanced analysis, provide the critical data clients need to help balance the financial, social and environmental aspects of doing business.
As part of the expense management services, Ecova analyzes and audits invoices, then presents consolidated bills on-line, and processes payments. Information gathered from invoices, providers and other customer-specific data allows Ecova to provide its clients with in-depth analytical support, real-time reporting and consulting services.
Ecova also provides a wide array of energy efficiency program management services to utilities across North America. As part of these management services, Ecova helps utilities develop and execute energy efficiency programs and can provide utilities with a complete turn-key solution.
The following table presents key statistics for Ecova:
 
2013
 
2012
 
2011
Expense management and utility customers at year-end
751

 
740

 
645

Billed sites at year-end
722,123

 
697,076

 
496,842

Dollars of customer energy spend managed (in billions)
$
20.9

 
$
19.4

 
$
18.3

Ecova's growth over the last several years in the key statistics listed above can be attributed to a combination of strategic acquisitions, new services and growth among existing customers, additional customers, and a high customer retention rate.
The noncontrolling interest of Ecova (which was 19.8 percent as of December 31, 2013) is primarily held by the previous owners of Cadence Network, a company acquired by Ecova in 2008.


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AVISTA CORPORATION



Other Businesses
The following table shows our assets related to our other businesses as of December 31 (dollars in thousands):
 
 
2013
 
2012
Spokane Energy
 
$
42,829

 
$
54,235

Avista Energy
 
12,399

 
12,549

METALfx
 
11,105

 
11,273

Steam Plant and Courtyard Office Center
 
7,055

 
7,122

Other
 
7,894

 
10,459

Total
 
$
81,282

 
$
95,638

Spokane Energy is a special purpose limited liability company and all of its membership capital is owned by Avista Corp. Spokane Energy was formed in December 1998, to assume ownership of a fixed rate electric capacity contract between Avista Corp. and Portland General Electric Company. Of the total assets for Spokane Energy, the fixed rate electricity capacity contract represents $40.6 million and $52.0 million for 2013 and 2012, respectively, and the likelihood of this asset being at risk of impairment is remote. In addition to the assets above, Spokane Energy also has nonrecourse long-term debt outstanding in the amount of $17.8 million and $32.8 million at December 31, 2013 and 2012, respectively, related to the acquisition of the fixed rate electric capacity contract. The final payment is due in January 2015 and Spokane Energy bears full recourse risk for the debt. See "Note 13 of the Notes to the Consolidated Financial Statements" for further information regarding this debt.
Avista Energy is a former electricity and natural gas marketing, trading and resource management business, which is a subsidiary of Avista Capital. This subsidiary has not been active since 2009; however, it continues to incur legal fees as it defends its actions related to several legal proceedings including the Federal Energy Regulatory Commission Inquiry, the
California Refund Proceeding, the Pacific Northwest Refund Proceeding, and the California Attorney General Complaint (the “Lockyer Complaint”). See "Note 20 of the Notes to the Consolidated Financial Statements" for further detail regarding these legal proceedings. The assets associated with Avista Energy are deferred tax assets related to its former operations.
Advanced Manufacturing and Development (AM&D) doing business as METALfx performs custom sheet metal fabrication of electronic enclosures, parts and systems for the computer, construction, telecom, renewable energy and medical industries.
Steam Plant and Courtyard Office Center consist of real estate investments (primarily commercial office buildings).
Our other investments and operations include emerging technology venture capital funds.
Over time as opportunities arise, we dispose of investments and phase out operations that do not fit with our overall corporate strategy. However, we may invest incremental funds to protect our existing investments and invest in new businesses that we believe fit with our overall corporate strategy.
We are focused on discovering new ways to accelerate growth for Avista Corp. within and adjacent to our core utility business and are planning to incur $2.0 million to $3.0 million of expense in 2014 exploring opportunities to develop new markets and ways for customers to improve the use of electricity and natural gas for commercial productivity and transportation. We may also make other targeted investments that will help us gain strategic insights to build new growth platforms.
Item 1A. Risk Factors
Risk Factors
The following factors could have a significant impact on our operations, results of operations, financial condition or cash flows. These factors could cause actual results or outcomes to differ materially from those discussed in our reports filed with the Securities and Exchange Commission (including this Annual Report on Form 10-K), and elsewhere. Please also see “Forward-Looking Statements” for additional factors which could have a significant impact on our operations, results of operations, financial condition or cash flows and could cause actual results to differ materially from those anticipated in such statements.
Weather (temperatures, precipitation levels and storms) has a significant effect on our results of operations, financial condition and cash flows.
Weather impacts are described in the following subtopics:
certain retail electricity and natural gas sales,

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AVISTA CORPORATION



the cost of natural gas supply,
the cost of power supply, and
damage to facilities.
Certain retail electricity and natural gas sales volumes vary directly with changes in temperatures. We normally have our highest retail (electric and natural gas) energy sales during the winter heating season in the first and fourth quarters of the year. We also have high electricity demand for air conditioning during the summer (third quarter). In general, warmer weather in the heating season and cooler weather in the cooling season will reduce our customers’ energy demand and retail operating revenues.
The cost of natural gas supply tends to increase with higher demand during periods of cold weather. Increased costs adversely affect cash flows when we purchase natural gas for retail supply at prices above the amount then allowed for recovery in retail rates. We defer differences between actual natural gas supply costs and the amount currently recovered in retail rates and we have generally been allowed to recover substantially all of these differences after regulatory review. However, these deferred costs require cash outflows from the time of natural gas purchases until the costs are later recovered through retail sales. Inter-regional natural gas pipelines and competition for supply can allow demand-driven price volatility in other regions of North America to affect prices in our region, even though there may be less extreme weather conditions in our area.
The cost of power supply can be significantly affected by weather. Precipitation (consisting of snowpack, its water content and melting pattern plus rainfall) and other streamflow conditions (such as regional water storage operations) significantly affect hydroelectric generation capability. Variations in hydroelectric generation inversely affect our reliance on market purchases and thermal generation. To the extent that hydroelectric generation is less than normal, significantly more costly power supply resources must be acquired and the ability to realize net benefits from surplus hydroelectric wholesale sales is reduced. Wholesale prices also vary based on wind patterns as wind generation capacity is material in our region but its contribution to supply is inconsistent.
The price of power in the wholesale energy markets tends to be higher during periods of high regional demand, such as occurs with temperature extremes. We may need to purchase power in the wholesale market during peak price periods. The price of natural gas as fuel for natural gas-fired electric generation also tends to increase during periods of high demand which are often related to temperature extremes. We may need to purchase natural gas fuel in these periods of high prices to meet electric demands. The cost of power supply during peak usage periods may be higher than the retail sales price or the amount allowed in retail rates by our regulators. To the extent that power supply costs are above the amount allowed currently in retail rates, the difference is partially absorbed by the Company in current expense and it is partially deferred or shared with customers through regulatory mechanisms.
The price of power tends to be lower during periods with excess supply, such as the spring when hydroelectric conditions are usually at their maximum and various facilities are required to operate to meet environmental mandates. Oversupply can be exacerbated when intermittent resources such as wind generation are producing output that may be supported by price subsidies. In extreme situations, we may be required to sell excess energy at negative prices.
As a result of these combined factors, our net cost of power supply – the difference between our costs of generation and market purchases, reduced by our revenue from wholesale sales – varies significantly because of weather.
Damage to facilities may be caused by severe weather, such as snow, ice or wind storms. The cost to implement rapid repair to such facilities can be significant. Overhead electric lines are most susceptible to damage caused by severe weather.
Regulators may not grant rates that provide timely or sufficient recovery of our costs or allow a reasonable rate of return for our shareholders.
We have historically experienced higher costs for utility operations in each of the last several years with the exception of 2013 which saw a slight decrease from 2012 actual costs. We have also made significant capital investments into utility plant assets. Our ability to recover these costs depends on the amount and timeliness of retail rate changes allowed by regulatory agencies. We expect to periodically file for rate increases with regulatory agencies to recover our costs and provide an opportunity to earn a reasonable rate of return for shareholders. If regulators grant substantially lower rate increases than our requests in the future or if deferred costs are disallowed, it could have a negative effect on our operating revenues, net income and cash flows. In addition, provisions to our approved settlement in the Washington general rate cases in 2012 and our approved settlement to the Idaho general rate cases in 2013, do not prevent us from filing general rate cases in these two jurisdictions in 2014; however, new rates from these general rate case filings would not take effect prior to January 1, 2015.


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AVISTA CORPORATION



Energy commodity price changes affect our cash flows and results of operations.
Energy commodity prices can be volatile. A combination of factors exposes our operations to commodity price risks. We rely on energy markets and other counterparties for energy supply, surplus and optimization transactions and commodity price hedging. These factors include:
Our obligation to serve our retail customers at rates set through the regulatory process. We cannot change retail rates to reflect current energy prices unless and until we receive regulatory approval.
Customer demand, which is beyond our control because of weather, customer choices, prevailing economic conditions and other factors.
Some of our energy supply cost is fixed by nature of the energy-producing assets or through contractual arrangements. However, a significant portion of our energy resource costs are not fixed.
Because we must supply the amount of energy demanded by our customers and we must sell it at fixed rates and only a portion of our energy supply costs are fixed, we are subject to the risk of buying energy at higher prices in wholesale energy markets (and the risk of selling energy at lower prices if we are in a surplus position). Electricity and natural gas in wholesale markets are commodities with historically high price volatility. Changes in wholesale energy prices affect, among other things, the cash requirements to purchase electricity and natural gas for retail customers or wholesale obligations and the market value of derivative assets and liabilities.
When we enter into fixed price energy commodity transactions for future delivery, we are subject to credit terms that may require us to provide collateral to wholesale counterparties related to the difference between current prices and the agreed upon fixed prices. These collateral requirements can place significant demands on our cash flows or borrowing arrangements. Price volatility can cause collateral requirements to change quickly and significantly.
Cash flow deferrals related to energy commodities can be significant. We are permitted to collect from customers only amounts approved by regulatory commissions. However, our costs to provide energy service can be much higher or lower than the amounts currently billed to customers. We are permitted to defer most of this difference for review by the regulatory commissions who have discretion as to the extent and timing of future recovery or refund to customers.
Power and natural gas costs higher than those recovered in retail rates reduce cash flows. Amounts that are not allowed for deferral or which are not approved to become part of customer rates affect our results of operations.
We defer income statement recognition and recovery from customers of certain power and natural gas costs that are higher or lower than what are currently authorized in retail rates by regulators. These power and natural gas costs are recorded as deferred charges with the opportunity for future recovery through retail rates. These deferred costs are subject to review for prudence and potential disallowance by regulators.
Despite the opportunity to recover deferred power and natural gas costs, our operating cash flows can be negatively affected until these costs are recovered from customers.
Our energy resource risk management processes can cause volatility in our cash flows and results of operations. We engage in active hedging and resource optimization practices to reduce energy cost volatility and economic exposure related to commodity price fluctuations. We routinely enter into contracts to hedge a portion of our purchase and sale commitments for electricity and natural gas, as well as forecasted excess or deficit energy positions and inventories of natural gas. We use physical energy contracts and derivative instruments, such as forwards, futures, swaps and options traded in the over-the-counter markets or on exchanges. We cannot and do not attempt to fully hedge our energy resource assets or our forecasted net positions for various time horizons. To the extent we have positions that are not hedged, or if hedging positions do not fully match the corresponding purchase or sale, fluctuating commodity prices could have a material effect on our operating revenues, resource costs, derivative assets and liabilities, and operating cash flows. In addition, actual loads and resources typically vary from forecasts, sometimes to a significant degree, which require additional transactions or dispatch decisions that impact cash flows. 
The hedges we enter into are reviewed for prudence by the various regulators and any deferred costs (including those as a result of our hedging transactions) are subject to review for prudence and potential disallowance by regulators.




19


AVISTA CORPORATION



We rely on regular access to financial markets but we cannot assure favorable or reasonable financing terms will be available when we need them.
Access to capital markets is critical to our operations and our capital structure. We have significant capital requirements that we expect to fund, in part, by accessing capital markets. As such, the state of financial markets and credit availability in the global, United States and regional economies impacts our financial condition. We could experience increased borrowing costs or limited access to capital on reasonable terms.
We access long-term capital markets to finance capital expenditures, repay maturing long-term debt and obtain additional working capital from time to time. Our ability to access capital on reasonable terms is subject to numerous factors and market conditions, many of which are beyond our control. If we are unable to obtain capital on reasonable terms, it may limit or prohibit our ability to finance capital expenditures and repay maturing long-term debt. Our liquidity needs could exceed our short-term credit availability and lead to defaults on various financing arrangements. We would also likely be prohibited from paying dividends on our common stock.
Performance of the financial markets could also result in significant declines in the market values of assets held by our pension plan and/or a significant increase in the pension liability (which impacts the funded status of the plan) and could increase future funding obligations and pension expense.
We rely on credit from financial institutions for short-term borrowings. We need adequate levels of credit with financial institutions for short-term liquidity. We have a $400.0 million committed line of credit that is scheduled to expire in February 2017. There is no assurance that we will have access to credit beyond the expiration date. The committed line of credit agreement contains customary covenants and default provisions. In the event of default, it would be difficult for us to obtain financing on reasonable terms to pay creditors or fund operations. We would also likely be prohibited from paying dividends on our common stock.
Ecova has a $125.0 million committed line of credit agreement with various financial institutions that has an expiration date of July 2017. There is no assurance that Ecova will have access to credit beyond the expiration date, and if conditions in financial markets deteriorate, it may affect the access to and cost of reliable credit. The committed line of credit agreement contains customary covenants and default provisions, and based on certain covenant conditions contained in the credit agreement, at December 31, 2013, Ecova could borrow an additional $35.3 million and still be compliant with the covenants. The covenant restrictions are calculated on a rolling twelve month basis, so this additional borrowing capacity could increase or decrease or Ecova could be required to pay down the outstanding debt as future results change. See further discussion of the specific covenants in "Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations - Ecova Credit Agreement." In the event of default, it would be difficult for Ecova to obtain financing on reasonable terms to pay creditors or fund operations.
Downgrades in our credit ratings could impede our ability to obtain financing, adversely affect the terms of financing and impact our ability to transact for or hedge energy resources. If we do not maintain our investment grade credit rating with the major credit rating agencies, we could expect increased debt service costs, limitations on our ability to access capital markets or obtain other financing on reasonable terms, and requirements to provide collateral (in the form of cash or letters of credit) to lenders and counterparties. In addition, credit rating downgrades could reduce the number of counterparties willing to do business with us.
We are subject to various operational and event risks.
Our operations are subject to operational and event risks that include:
blackouts or disruptions to distribution, transmission or transportation systems,
forced outages at generating plants,
fuel cost and availability, including delivery constraints,
explosions, fires, accidents, or mechanical breakdowns that may occur while operating and maintaining our generation, transmission and distribution systems, and
natural disasters that can disrupt energy generation, transmission and distribution and general business operations.
Disasters may affect the general economy, financial and capital markets, specific industries, or the Company's ability to conduct business. As protection against operational and event risks, we maintain business continuity and disaster recovery plans, maintain insurance coverage against some, but not all, potential losses and we seek to negotiate indemnification arrangements

20


AVISTA CORPORATION



with contractors for certain event risks. However, insurance or indemnification agreements may not be adequate to protect us against liability, extra expenses and operating disruptions from all of the operational and event risks described above. In addition, we are subject to the risk that insurers and/or other parties will dispute or be unable to perform on their obligations to us.
Ecova participates in a competitive environment and may be unable to attain the level or timeliness of growth we expect.
Ecova operates in a highly competitive market, with many competitors vying for the same clients and services. Some current and potential new entrants to the market could have greater access to capital than Ecova, more visible name recognition, or could develop products and services that directly compete with Ecova’s offerings and be more attractive to current or potential Ecova clients. While Ecova strives to maintain client satisfaction standards, competitive pressure could affect client retention and results of operations. If demand for Ecova’s energy efficiency and renewable energy solutions does not develop as we expect, or if certain federal, state, or local government support for energy efficiency programs declines, our revenue could decrease and our results of operations could decline. Ecova also encounters competition from energy efficiency technology advances and may or may not continue to maintain or grow its marketplace presence because of these and other factors.
Ecova's operations have been partially assembled through numerous acquisitions and may include other acquisitions in the future as opportunities warrant. There are various uncertainties involved with launching new products and services, expanding to new markets, assimilating acquired operations, achieving revenue growth and operating synergies from acquired operations. Past and future acquisitions, domestically or internationally, if any, could disrupt the business and may or may not be accretive to earnings or provide the expected client offerings, market position, key personnel, or technology, or could introduce an expanded risk profile to Ecova’s operations. Additionally, changes in investment returns or payment and processing activities could affect results of operations. Ecova's growth and its ability to manage costs within its competitive marketplace and emerging business processes could make it more difficult to accurately forecast cash flows and results of operations. As a result, earnings projections may not be achieved or may be more volatile and cash flows may be irregular in this business segment.
Cyber attacks, terrorism or other malicious acts could disrupt our businesses and have a negative impact on our results of operations and cash flows.

In the course of our operations, we rely on interconnected technology systems for operation of our generating plants, electric transmission and distribution systems, natural gas distribution systems, customer billing and customer service, accounting and other administrative processes and compliance with various regulations. Ecova also relies on remote access interconnected technology for the performance of services and client deliverables, and some of Ecova's clients rely upon Ecova for 24/7 energy monitoring services. For Ecova to deliver such services, Ecova relies upon technology from suppliers and third party service providers, which could be subject to interruption.

There are various risks associated with technology systems such as hardware or software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, programming mistakes and other deliberate or inadvertent human errors. In particular, cyber attacks, terrorism or other malicious acts could damage, destroy or disrupt these systems. Additionally, the facilities and systems of clients, suppliers and third party service providers could be vulnerable to these same risks and, to the extent of interconnection to our technology, may impact us. Any failure, unexpected, or unauthorized unavailability of technology systems could result in a loss of operating revenues, an increase in operating expenses and costs to repair or replace damaged assets. Any of the above could also result in the loss or release of confidential customer information or other proprietary data that could adversely affect our reputation, competitiveness, and result in costly litigation and impact on our results of operations. As these potential cyber attacks become more common and sophisticated, we could be required to incur costs to strengthen our systems and respond to emerging concerns.
We are currently the subject of several regulatory proceedings, and we are named in multiple lawsuits related to our participation in western energy markets.
Through our utility operations and the prior operations of Avista Energy, we are involved in a number of legal and regulatory proceedings and complaints related to energy markets in the western United States. Most of these proceedings and complaints relate to the significant increase in the spot market price of energy in 2000 and 2001. This allegedly contributed to or caused unjust and unreasonable prices. These proceedings and complaints include, but are not limited to:
refund proceedings in California and the Pacific Northwest,
market conduct investigations by the FERC, and
complaints filed by various parties related to alleged misconduct by parties in western power markets.

21


AVISTA CORPORATION



As a result of these proceedings and complaints, certain parties have asserted claims for significant refunds and damages from us, which could result in a negative effect on our results of operations and cash flows. See “Note 20 of the Notes to Consolidated Financial Statements” for further information.
There have been numerous recent changes in legislation, related administrative rulemaking, and Executive Orders, including periodic audits of compliance with such rules, which may adversely affect our operational and financial performance.
We expect to continue to be affected by legislation at the national, state and local level, as well as by administrative rules and requirements published by government agencies, including but not limited to the FERC, the EPA and state regulators. We are also subject to NERC and WECC reliability standards. The FERC, the NERC and the WECC may perform periodic audits of the Company. Failure to comply with the FERC, the NERC, or the WECC requirements can result in financial penalties of up to $1 million per day per violation.
Future legislation or administrative rules could have a material adverse effect on our operations, results of operations, financial condition and cash flows.
Actions or limitations to address concerns over the long-term global and Pacific Northwest climate changes may affect our operations and financial performance.
Legislative developments and advocacy at the state, national and international levels concerning climate change and other environmental issues could have significant impacts on our operations. The electric utility industry is one of the largest and most immediate industries to be more heavily regulated in some proposals. For example, various legislative proposals have been made to limit or place further restrictions on byproducts of combustion, including sulfur dioxide, nitrogen oxide, carbon dioxide, and other greenhouse gases and mercury emissions. Such proposals, if adopted, could restrict the operation and raise the cost of our power generation resources.
We expect continuing activity in the future and we are evaluating the extent that potential changes to environmental laws and regulations may:
increase the operating costs of generating plants,
increase the lead time and capital costs for the construction of new generating plants,
require modification of our existing generating plants,
require existing generating plant operations to be curtailed or shut down,
reduce the amount of energy available from our generating plants,
restrict the types of generating plants that can be built or contracted with, and
require construction of specific types of generation plants at higher cost.
 
We have contingent liabilities, including certain matters related to potential environmental liabilities, and cannot predict the outcome of these matters.
In the normal course of our business, we have matters that are the subject of ongoing litigation, mediation, investigation and/or negotiation. We cannot predict the ultimate outcome or potential impact of any particular issue, including the extent, if any, of insurance coverage or that amounts payable by us may be recoverable through the ratemaking process. We are subject to environmental regulation by federal, state and local authorities related to our past, present and future operations. See “Note 20 of the Notes to Consolidated Financial Statements” for further details of these matters.
We may be adversely affected by our inability to successfully implement certain technology projects.
We are currently undertaking a multi-year technology project to replace our customer information and work management systems, which is expected to be completed by the end of 2014. Our customer information and work management systems are two of our most critical technology systems and are interconnected to many other systems in our company. Implementation of these information systems is complex, expensive and time consuming. If we do not successfully implement the new systems, or if the systems do not operate as intended, it could result in substantial disruptions to our business, which could have a material adverse effect on our results of operations and financial condition.



22


AVISTA CORPORATION



Our planned transaction with AERC may not achieve its intended results.
On November 4, 2013, we entered into an agreement and plan of merger with AERC, a privately-held company based in Juneau, Alaska. If the transaction is completed, AERC will become a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEL&P, the sole provider of electric services to approximately 16,000 customers in the City and Borough of Juneau, Alaska. The transaction is expected to close by July 1, 2014, following the approval of the merger transaction by the requisite number of AERC shareholders, the receipt of necessary regulatory approvals and the satisfaction of other closing conditions. We expect that the addition of AERC will be slightly dilutive to earnings per share in 2014, and that it will be slightly accretive to earnings per share in 2015. The transaction is expected to result in the recording of a significant amount of goodwill (currently estimated at $48 million). Achieving the anticipated accretive earnings per share contribution from AERC is subject to numerous uncertainties, including market conditions and risks related to AERC's business. This transaction could result in increased costs (including integration costs), decreases in the expected revenues from AERC, the impairment of goodwill or other assets, and diversion of management time and resources, which could have a material adverse effect on our results of operations, financial condition and cash flows.
Item 1B. Unresolved Staff Comments
As of the filing date of this Annual Report on Form 10-K, we have no unresolved comments from the staff of the Securities and Exchange Commission.
Item 2. Properties
Avista Utilities
Substantially all of our utility properties are subject to the lien of our mortgage indenture.
Our utility electric properties, located in the states of Washington, Idaho, Montana and Oregon, include the following:

23


AVISTA CORPORATION



Generation Properties
 
No. of
Units
 
Nameplate
Rating
(MW) (1)
 
Present
Capability
(MW) (2)
Hydroelectric Generating Stations (River)
 
 
 
 
 
Washington:
 
 
 
 
 
Long Lake (Spokane)
4
 
70.0

 
88.0

Little Falls (Spokane)
4
 
32.0

 
35.6

Nine Mile (Spokane) (3)
4
 
26.4

 
22.4

Upper Falls (Spokane)
1
 
10.0

 
10.2

Monroe Street (Spokane)
1
 
14.8

 
15.0

Idaho:
 
 
 
 
 
Cabinet Gorge (Clark Fork) (4)
4
 
265.0

 
273.0

Post Falls (Spokane)
6
 
14.8

 
15.4

Montana:
 
 
 
 
 
Noxon Rapids (Clark Fork)
5
 
487.8

 
562.4

Total Hydroelectric
 
 
920.8

 
1,022.0

Thermal Generating Stations
 
 
 
 
 
Washington:
 
 
 
 
 
Kettle Falls GS
1
 
50.7

 
53.5

Kettle Falls CT
1
 
7.2

 
6.9

Northeast CT
2
 
61.8

 
64.8

Boulder Park
6
 
24.6

 
24.0

Idaho:
 
 
 
 
 
Rathdrum CT
2
 
166.5

 
166.5

Montana:
 
 
 
 
 
Colstrip Units 3 and 4 (5)
2
 
233.4

 
222.0

Oregon:
 
 
 
 
 
Coyote Springs 2
1
 
287.0

 
284.4

Total Thermal
 
 
831.2

 
822.1

Total Generation Properties
 
 
1,752.0

 
1,844.1


(1)
Nameplate Rating, also referred to as “installed capacity,” is the manufacturer’s assigned power capability under specified conditions.
(2)
Present capability is the maximum capacity of the plant under standard test conditions without exceeding specified limits of temperature, stress and environmental conditions. Information is provided as of December 31, 2013.
(3)
There are currently four units at the Nine Mile plant; however, Units 1 and 2 are currently not running due to a mechanical failure. A project is underway to replace these units and restore capability. The present capability disclosed above represents the capability of the two running units, which have a nameplate rating of 18 MW.
(4)
For Cabinet Gorge, we have water rights permitting generation up to 265 MW. However, if natural stream flows will allow for generation above our water rights we are able to generate above our water rights. If natural stream flows only allow for generation at or below 265 MW, we are limited to generation of 265 MW. The present capability disclosed above represents the capability based on maximum stream flow conditions when we are allowed to generate above our water rights.
(5)
Jointly owned; data refers to our 15 percent interest.
Electric Distribution and Transmission Plant
We own and operate approximately 19,000 miles of primary and secondary electric distribution lines providing service to retail customers. We have an electric transmission system of 685 miles of 230 kV line and 1,534 miles of 115 kV line. We also own an 11 percent interest in approximately 500 miles of a 500 kV line between Colstrip, Montana and Townsend, Montana. Our transmission and distribution systems also include numerous substations with transformers, switches, monitoring and metering devices, and other equipment.

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AVISTA CORPORATION



The 230 kV lines are the backbone of our transmission grid and are used to transmit power from generation resources, including Noxon Rapids, Cabinet Gorge and the Mid-Columbia hydroelectric projects, to the major load centers in our service area, as well as to transfer power between points of interconnection with adjoining electric transmission systems. These lines interconnect at various locations with the Bonneville Power Administration (BPA), Grant County PUD, PacifiCorp, NorthWestern Energy and Idaho Power Company and serve as points of delivery for power from generating facilities outside of our service area, including Colstrip, Coyote Springs 2 and the Lancaster Plant.
These lines also provide a means for us to optimize resources by entering into short-term purchases and sales of power with entities within and outside of the Pacific Northwest.
The 115 kV lines provide for transmission of energy and the integration of smaller generation facilities with our service-area load centers, including the Spokane River hydroelectric projects, the Kettle Falls projects, Rathdrum CT, Boulder Park and the Northeast CT. These lines interconnect with the BPA, Chelan County PUD, the Grand Coulee Project Hydroelectric Authority, Grant County PUD, NorthWestern Energy, PacifiCorp and Pend Oreille County PUD. Both the 115 kV and 230 kV interconnections with the BPA are used to transfer energy to facilitate service to each other’s customers that are connected through the other’s transmission system. We hold a long-term transmission agreement with the BPA that allows us to serve our native load customers that are connected through the BPA’s transmission system. During 2013 we reached a settlement with BPA whereby they reimbursed us $11.7 million for past use of our transmission system. In addition, BPA agreed to pay an additional $0.3 million monthly ($3.2 million annually) for the use of our transmission system commencing on January 1, 2013. See "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Bonneville Power Administration Reimbursement and Reardan Wind Generation Project" for additional details surrounding this settlement agreement.
Natural Gas Plant
We have natural gas distribution mains of approximately 3,400 miles in Washington, 1,960 miles in Idaho and 2,300 miles in Oregon. We have natural gas transmission mains of approximately 75 miles in Washington and 50 miles in Oregon. Our natural gas system includes numerous regulator stations, service distribution lines, monitoring and metering devices, and other equipment.
We own a one-third interest in Jackson Prairie, an underground natural gas storage field located near Chehalis, Washington. Jackson Prairie has a total peak day deliverability of 11.5 million therms, with a total working natural gas capacity of 253 million therms. As an owner, our share is one-third of the peak day deliverability and total working capacity. Natural gas storage enables us to store gas in the summer when prices are traditionally lower and withdraw during higher priced winter months. Natural gas storage is also used as a variable peaking resource during cold weather events.
Item 3. Legal Proceedings
See “Note 20 of Notes to Consolidated Financial Statements” for information with respect to legal proceedings.
Item 4. Mine Safety Disclosures
Not applicable.


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AVISTA CORPORATION



PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is currently listed on the New York Stock Exchange under the ticker symbol “AVA.” As of January 31, 2014, there were 9,637 registered shareholders of our common stock.
The Board of Directors considers the level of dividends on our common stock on a regular basis, taking into account numerous factors including, without limitation:
our results of operations, cash flows and financial condition,
the success of our business strategies, and
general economic and competitive conditions.
Our net income available for dividends is generally derived from our regulated utility operations.
The payment of dividends on common stock could be limited by:
certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of Incorporation, as amended (currently there are no preferred shares outstanding),
certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements (see Item 7. Management's Discussion and Analysis - "Capital Resources" for compliance with these covenants), and
the hydroelectric licensing requirements of section 10(d) of the Federal Power Act, as amended (FPA) (see “Note 1 of Notes to Consolidated Financial Statements”).
On February 7, 2014, Avista Corp.’s Board of Directors declared a quarterly dividend of $0.3175 per share on the Company’s common stock. This was an increase of $0.0125 per share, or 4 percent from the previous quarterly dividend of $0.305 per share.
For additional information, see “Notes 1, 17, 18 and 19 of Notes to Consolidated Financial Statements.”
The following table presents quarterly high and low stock prices as reported on the consolidated reporting system, as well as dividend information:
 
Three Months Ended
 
March
31
 
June
30
 
September
30
 
December
31
2013
 
 
 
 
 
 
 
Dividends paid per common share
$
0.305

 
$
0.305

 
$
0.305

 
$
0.305

Trading price range per common share:

 

 

 

High
$
27.48

 
$
29.26

 
$
29.21

 
$
28.45

Low
$
24.10

 
$
25.68

 
$
25.55

 
$
25.88

2012
 
 
 
 
 
 
 
Dividends paid per common share
$
0.29

 
$
0.29

 
$
0.29

 
$
0.29

Trading price range per common share:

 

 

 

High
$
26.18

 
$
27.07

 
$
28.05

 
$
26.77

Low
$
24.48

 
$
24.95

 
$
25.07

 
$
22.78

For information with respect to securities authorized for issuance under equity compensation plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.”

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AVISTA CORPORATION



Item 6. Selected Financial Data
 
(in thousands, except per share data and ratios)
Years Ended December 31,
 
2013
 
2012
 
2011
 
2010
 
2009
Operating Revenues:
 
 
 
 
 
 
 
 
 
Avista Utilities
$
1,403,995

 
$
1,354,185

 
$
1,443,322

 
$
1,419,646

 
$
1,395,201

Ecova
176,761

 
155,664

 
137,848

 
102,035

 
77,275

Other
39,549

 
38,953

 
40,410

 
61,067

 
40,089

Intersegment eliminations
(1,800
)
 
(1,800
)
 
(1,800
)
 
(24,008
)
 

Total
$
1,618,505

 
$
1,547,002

 
$
1,619,780

 
$
1,558,740

 
$
1,512,565

Income (Loss) from Operations (pre-tax):
 
 
 
 
 
 
 
 
 
Avista Utilities
$
232,572

 
$
188,778

 
$
202,373

 
$
198,200

 
$
188,511

Ecova
13,304

 
2,972

 
20,917

 
15,865

 
11,603

Other
(1,483
)
 
(1,680
)
 
4,714

 
5,669

 
(7,103
)
Total
$
244,393

 
$
190,070

 
$
228,004

 
$
219,734

 
$
193,011

Net income
$
112,294

 
$
78,800

 
$
103,539

 
$
94,948

 
$
88,648

Net income attributable to noncontrolling interests
$
(1,217
)
 
$
(590
)
 
$
(3,315
)
 
$
(2,523
)
 
$
(1,577
)
Net Income (Loss) attributable to Avista Corporation shareholders:
Avista Utilities
$
108,598

 
$
81,704

 
$
90,902

 
$
86,681

 
$
86,744

Ecova
7,129

 
1,825

 
9,671

 
7,433

 
5,329

Other
(4,650
)
 
(5,319
)
 
(349
)
 
(1,689
)
 
(5,002
)
Total
$
111,077

 
$
78,210

 
$
100,224

 
$
92,425

 
$
87,071

Average common shares outstanding, basic
59,960

 
59,028

 
57,872

 
55,595

 
54,694

Average common shares outstanding, diluted
59,997

 
59,201

 
58,092

 
55,824

 
54,942

Common shares outstanding at year-end
60,077

 
59,813

 
58,423

 
57,120

 
54,837

Income from continuing operations per Avista Corporation common share:
Diluted
$
1.85

 
$
1.32

 
$
1.72

 
$
1.65

 
$
1.58

Basic
$
1.85

 
$
1.32

 
$
1.73

 
$
1.66

 
$
1.59

Dividends declared per common share
$
1.22

 
$
1.16

 
$
1.10

 
$
1.00

 
$
0.81

Book value per common share
$
21.61

 
$
21.06

 
$
20.30

 
$
19.71

 
$
19.17

Total Assets at Year-End:
 
 
 
 
 
 
 
 
 
Avista Utilities
$
3,940,998

 
$
3,894,821

 
$
3,809,446

 
$
3,589,235

 
$
3,400,384

Ecova
339,643

 
322,720

 
292,940

 
221,086

 
143,060

Other
81,282

 
95,638

 
112,145

 
129,774

 
63,515

Total
$
4,361,923

 
$
4,313,179

 
$
4,214,531

 
$
3,940,095

 
$
3,606,959

Long-Term Debt and Capital Leases (including current portion)
$
1,272,783

 
$
1,228,739

 
$
1,177,300

 
$
1,101,857

 
$
1,071,338

Nonrecourse Long-Term Debt of Spokane
 
 
 
 
 
 
 
 
 
Energy (including current portion)
$
17,838

 
$
32,803

 
$
46,471

 
$
58,934

 
$

Long-Term Debt to Affiliated Trusts
$
51,547

 
$
51,547

 
$
51,547

 
$
51,547

 
$
51,547

Total Avista Corporation Shareholders’ Equity
$
1,298,266

 
$
1,259,477

 
$
1,185,701

 
$
1,125,784

 
$
1,051,287

Ratio of Earnings to Fixed Charges (1)
3.10

 
2.47

 
3.06

 
2.86

 
2.95

(1)
See Exhibit 12 for computations.

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AVISTA CORPORATION



Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Business Segments
We have two reportable business segments as follows:
Avista Utilities – an operating division of Avista Corp. that comprises our regulated utility operations. Avista Utilities generates, transmits and distributes electricity and distributes natural gas serving electric and gas customers in eastern Washington and northern Idaho and gas customers in parts of Oregon. The utility also engages in wholesale purchases and sales of electricity and natural gas.
Ecova – an indirect subsidiary of Avista Corp. (80.2 percent owned as of December 31, 2013) that provides energy efficiency and cost management programs and services for multi-site customers and utilities throughout North America. Ecova's service lines include expense management services for utility and telecom needs as well as strategic energy management and efficiency services that include procurement, conservation, performance reporting, financial planning, facility optimization and continuous monitoring, and energy efficiency program management for commercial enterprises and utilities.

We have other businesses, including sheet metal fabrication, venture fund investments and real estate investments, as well as certain other operations of Avista Capital. These activities do not represent a reportable business segment and are conducted by various direct and indirect subsidiaries of Avista Corp., including AM&D, doing business as METALfx.
The following table presents net income (loss) attributable to Avista Corp. shareholders for each of our business segments (and the other businesses) for the year ended December 31 (dollars in thousands):
 
2013
 
2012
 
2011
Avista Utilities
$
108,598

 
$
81,704

 
$
90,902

Ecova
7,129

 
1,825

 
9,671

Other
(4,650
)
 
(5,319
)
 
(349
)
Net income attributable to Avista Corporation shareholders
$
111,077

 
$
78,210

 
$
100,224

Executive Level Summary
Overall Results
Net income attributable to Avista Corporation shareholders was $111.1 million for 2013, an increase from $78.2 million for 2012. This was due to an increase in earnings at Avista Utilities and Ecova and a decrease in losses at the other businesses. Earnings at Avista Utilities increased due to the implementation of general rate increases, weather that was warmer in the summer cooling season and colder in the fourth quarter heating season, the net benefit from the settlement with BPA, and a slight reduction in other operating expenses. These were partially offset by expected increases in depreciation and amortization and taxes other than income taxes. Net income at Ecova increased due to increased revenues associated with new services, expense and data management services, and energy management services. This was partially offset by higher other operating expenses and increased depreciation and amortization. These results, including a quantification of their respective impacts, are discussed in detail below.
Avista Utilities
Avista Utilities is our most significant business segment. Our utility financial performance is dependent upon, among other things:
weather conditions (temperatures, precipitation levels and wind patterns) which affect energy demand and electric generation, including the effect of precipitation and temperature on hydroelectric resources, the effect of wind patterns on wind-generated power, weather-sensitive customer demand, and similar impacts on supply and demand in the wholesale energy markets,
regulatory decisions, allowing our utility to recover costs, including purchased power and fuel costs, on a timely basis, and to earn a reasonable return on investment,
the price of natural gas in the wholesale market, including the effect on the price of fuel for generation, and
the price of electricity in the wholesale market, including the effects of weather conditions, natural gas prices and other factors affecting supply and demand.


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AVISTA CORPORATION



Forecasted Customer and Load Growth
Based on our forecasts for our utility operations for 2014 through 2017, we expect annual electric customer growth to average 0.7 percent to 1.4 percent per year and annual natural gas customer growth to average 0.7 percent to 1.5 percent within our service area. We anticipate retail electric load growth to average between 0.5 percent and 1.0 percent and natural gas load growth to average between 0.7 percent and 1.5 percent. We anticipate customer and load growth at the lower end of the range in 2014 and a modest recovery as the economy strengthens during the four-year period. While the number of electric and natural gas customers is growing, the average annual usage by each residential customer has not changed significantly.
For further discussion regarding utility customer growth, load growth, and the general economic conditions in our service territory, see "Economic Conditions and Utility Load Growth."
See also "Competition" for a discussion of competitive factors that could affect our results of operations in the future.
General Rate Cases
In our utility operations, we regularly review the need for rate changes in each jurisdiction to improve the recovery of costs and capital investments in our generation, transmission and distribution systems. The following are the recent general rate increases that have occurred or will go into effect in the near future.
Jurisdiction
 
Service
 
Effective Date
Washington
 
Electric and Natural Gas
 
January 1, 2012
 
 
Electric and Natural Gas
 
January 1, 2013 (1) (3)
 
 
Electric and Natural Gas
 
January 1, 2014 (1) (3)
Idaho
 
Electric and Natural Gas
 
October 1, 2011
 
 
Natural Gas
 
April 1, 2013 (2) (3)
 
 
Electric and Natural Gas
 
October 1, 2013 (2) (3)
Oregon
 
Natural Gas
 
June 1, 2012
 
 
Natural Gas
 
February 1, 2014 (4)
 
 
Natural Gas
 
November 1, 2014 (4)
(1)
Relates to a settlement agreement in our Washington general rate cases (originally filed on April 2, 2012), which was approved by the UTC in December 2012 (see further discussion below under "Washington General Rate Cases").
(2)
Relates to a settlement agreement in our Idaho general rate cases (originally filed on October 11, 2012), which was approved by the IPUC in March 2013 (see further discussion below under "Idaho General Rate Cases").
(3)
Included in the original settlement agreements is a provision that we will not file a general rate case in these jurisdictions seeking new rates to take effect before January 1, 2015. We filed general rate cases in Washington in February 2014 and we plan to file in Idaho in the second quarter of 2014 with proposed rates that would take effect on January 1, 2015. This provision does not preclude us from filing other rate adjustments such as PGAs.
(4)
Relates to a settlement agreement in our Oregon general rate case (originally filed in August 2013), which was approved by the OPUC in January 2014 (see further discussion below under "Oregon General Rate Case").
Capital Expenditures
We are making significant capital investments in generation, transmission and distribution systems to preserve and enhance service reliability for our customers and replace aging infrastructure. Utility capital expenditures were $294.4 million for 2013. We expect utility capital expenditures to be about $335 million for 2014 and $355 million in 2015. We increased our estimates for future capital expenditures from the previous estimates of $260 million annually in 2014 and 2015 due to the increased scope and costs of updating and maintaining our generation, transmission and energy distribution systems to ensure reliability. These estimates of capital expenditures are subject to continuing review and adjustment (see discussion under “Avista Utilities Capital Expenditures”).
Customer Contract Renewal
An agreement with one of our largest electric customers, which has consumed approximately 100 aMWs per year, expired on June 30, 2013. We negotiated a new agreement with this customer that became effective on July 1, 2013 which has a five-year term. A Joint Application requesting approval of the new agreement was approved by the IPUC on June 28, 2013. This

29


AVISTA CORPORATION



customer intends to generate a significant portion of its electricity requirements. Accordingly, under the new agreement, we expect a decrease in annual power sales to this customer of approximately $21 million and a resulting decrease in resource costs of approximately $19 million. According to the approved Joint Application, any change in revenues and expenses associated with the new agreement, as compared with the revenues and expenses included in the last general rate case for this customer, will be tracked through the PCA in Idaho at 100 percent, until such time as the contract is included in our base rates. As such, we expect no impact on our earnings from the new agreement.
Colstrip Generating Facility Outage
We own a 15 percent interest in Units 3 and 4 of the Colstrip Generating Plant in southeastern Montana, a coal-fired facility which is operated by PPL Montana, LLC. On July 1, 2013, an unplanned outage occurred to Colstrip Unit 4, with identified damage to the stator and rotor assembly. On January 23, 2014, the required repairs were completed and Unit 4 was returned to service. The total repair costs through December 31, 2013 were $26.9 million with our 15 percent share being $4.0 million. It is expected that these costs will be fully reimbursed less our portion of the $2.5 million insurance deductible ($0.4 million). Through December 31, 2013 we have received $3.0 million in insurance proceeds and we expect all costs related to the repairs to be accumulated and the remaining reimbursement from the insurance company to occur by mid-year 2014. The insurance reimbursement will be offset against the costs incurred throughout the project and we expect the final out-of-pocket costs of $0.4 million to be allocated between capital and operating expenses at approximately 90 percent and 10 percent, respectively.
The lost generation of Colstrip Unit 4 resulted in a combination of lower surplus wholesale sales and increased thermal fuel costs and purchased power costs to replace the energy, which resulted in increased net power supply costs. Our estimates showed an increase in power supply costs of approximately $12 million system-wide for 2013 as a result of the outage. All of the additional costs were included in the ERM in Washington and the PCA in Idaho. After consideration of the impacts of the two recovery mechanisms and the sharing between us and our customers, the outage was estimated to have a negative impact on gross margin (operating revenues less resource costs) in the range of approximately $6 million to $7 million for 2013. In addition, based on our calculations, the Colstrip Generating Plant dropped below a 70 percent availability factor during 2013. As a result, a provision associated with the ERM was triggered and an automatic prudence review surrounding the cause of the outage and the costs to replace the lost power will be performed by the UTC. We do not expect this prudence review to have a material impact on our cost recovery. In addition to the availability factor calculations, actual fixed costs of the plant must be compared to authorized costs and if the fixed costs are below authorized costs, the difference is credited back to customers through the ERM. Based on our calculations, the difference between actual and authorized fixed costs for 2013 was not material.
Alaska Energy and Resources Company Planned Transaction
On November 4, 2013, we entered into an agreement and plan of merger (Merger Agreement) with AERC, a privately-held company based in Juneau, Alaska. When the transaction is complete, AERC will become a wholly-owned subsidiary of Avista Corp.
The primary subsidiary of AERC is AEL&P, the sole provider of electric services to approximately 16,000 customers in the City and Borough of Juneau, Alaska. In 2012, AEL&P had annual revenues of $42 million and a total rate base of $111 million. The utility has a firm retail peak load of approximately 80 MW. AEL&P owns four hydroelectric generating facilities, having a total present capacity of 24.7 MW, and has a power purchase commitment for the output of the Snettisham hydroelectric project, having a present capacity of 78 MW, for a total hydroelectric capacity of 102.7 MW. AEL&P is not interconnected to any other electric system; therefore, the utility has 93.9 MW of diesel generating present capacity to provide back-up service to firm customers when necessary.
In addition to the regulated utility, AERC owns 100 percent of AJT Mining, which is an inactive mining company holding certain mining properties.
The merger consideration at closing will be $170 million, less AERC's indebtedness and subject to other customary closing adjustments. The transaction will be funded primarily through the issuance of Avista Corp. common stock to the shareholders of AERC. The transaction is expected to close by July 1, 2014, following the approval of the merger transaction by the requisite number of AERC shareholders, the receipt of necessary regulatory approvals and the satisfaction of other closing conditions. Avista Corp. shareholder approval is not required. We expect that the addition of AERC will be slightly dilutive to earnings per share in 2014, and that it will be slightly accretive to earnings per share in 2015.
The transaction is expected to result in the recording of a significant amount of goodwill, currently estimated at $48 million.
AEL&P currently has an authorized utility capital structure of 53.8 percent equity and an authorized return on equity of 12.875 percent. We expect that AEL&P will maintain this capital structure following the merger. The consolidated capital structure of AERC is expected to be similar to the capital structure of Avista Corp.

30


AVISTA CORPORATION



For additional information regarding the AERC transaction, including the valuation and number of shares of Avista Corp. common stock to be delivered to AERC shareholders, see “Note 4 of the Notes to Consolidated Financial Statements” and our Current Report on Form 8-K dated November 4, 2013.
Ecova
Ecova plans to continue to grow organically and possibly through strategic acquisitions. Ecova's acquisitions since 2008 have been funded through internally generated cash, borrowings under Ecova's credit facility and an equity infusion from existing shareholders. If Ecova's capital needs exceed its credit facility capacity or management determines a different capital structure is necessary, Ecova may require additional equity infusions from existing shareholders and/or new funding sources.
We may seek to monetize all or part of our investment in Ecova in the future. We regularly engage in discussions with potential investors and acquirors to explore opportunities for such a transaction. The value of a potential monetization would depend on future market conditions, growth of the business, transaction structure and other factors. A strategic change to Ecova's ownership structure could provide access to public market capital and provide potential liquidity to Avista Corp. and the other owners of Ecova. There can be no assurance that the terms for a proposed transaction, if any, would be acceptable to Avista Corp. or that any such transaction would be completed.
Liquidity and Capital Resources
We have a committed line of credit with various financial institutions in the total amount of $400.0 million with an expiration date of February 2017. As of December 31, 2013, there were $171.0 million of cash borrowings and $27.4 million in letters of credit outstanding leaving $201.6 million of available liquidity under this line of credit.
Ecova has a five-year $125.0 million committed line of credit agreement with various financial institutions that has an expiration date of July 2017. As of December 31, 2013, Ecova had $46.0 million of borrowings outstanding under its committed line of credit agreement. Based on certain covenant conditions contained in the credit agreement, at December 31, 2013, Ecova could borrow an additional $35.3 million and still be compliant with the covenants. The covenant restrictions are calculated on a rolling twelve month basis, so this additional borrowing capacity could increase or decrease or Ecova could be required to pay down the outstanding debt as future results change. See further discussion of the specific covenants below under "Ecova Credit Agreement."
In August 2013, we entered into a $90.0 million term loan agreement with an institutional investor bearing an annual interest rate of 0.84 percent and maturing in 2016. The net proceeds from the term loan agreement were used to repay a portion of corporate indebtedness in anticipation of the maturity of $50.0 million in First Mortgage Bonds which occurred in December 2013.
We expect to issue approximately $190.0 million of long-term debt during 2014, including about $90.0 million of debt issuances combined by AERC or AEL&P associated with rebalancing the consolidated capital structure at AERC. This amount assumes we are going to refinance the existing net debt, estimated to be about $25.0 million